Horizontal wells are now used extensively in the production of hydrocarbons from underground formations or reservoirs. Gravity drainage is an emerging technique that uses horizontal wells and it promises to greatly increase the economically recoverable reserves of oil. In a gravity drainage process, a typical well configuration involves paired horizontal wells: one for vapour injection; and a second one for liquid production. An extraction chamber is formed in the pay zone around the injection well generally above the production well. Fluids, mobilized by the recovery process, drain towards the bottom of the pay zone forming a liquid sump. Steam Assisted Gravity Drainage (SAGD) is one form of gravity drainage extraction, carbon dioxide enhanced oil recovery is another emerging gravity process for conventional and heavy oil which may grow in importance due to carbon capture and storage.
In a gravity drainage process, the production well is located towards the bottom of the pay zone so it is preferentially submerged in draining liquids. The vapour and extraction chamber expand upward and outward as more fluids drain towards the bottom of the chamber. The production well, located within a well casing, is typically divided into two main sections—a generally horizontal inflow section that contains perforations, screens, slots or the like to permit fluid to flow into the well casing while keeping out sand and the like, and a riser section that has no perforations and acts as a fluid conduit to bring fluids to surface. The riser section may be generally vertical or may be sloped depending upon the reservoir depth and drilling pattern used.
It is currently understood that an efficient gravity drainage process ensures that mostly liquid is withdrawn from the chamber through the production well. The prior art teaches that this can be achieved by restricting the production from the well to ensure that the horizontal portion of the production well and thus the inlet perforations are always submerged under liquid in a sump. This liquid submergence is supposed to prevent vapour, being injected at pressure into the chamber above from passing directly into the production well without any beneficial extraction or oil mobilization effect. Any vapour that passes into the production well represents a loss of efficiency for the extraction process because it is unable to deliver its latent heat and/or its solvent content to the oil to be recovered.
Even in the case of gas assisted gravity drainage, where an inert gas is injected into the vapour chamber without any intention of mobilizing the oil but simply to help fill the voidage volume in the extraction chamber, the loss of gas into the production well is undesirable. Typically any such vented gas must be separated at surface from the produced fluids, dried, recompressed and re-injected at considerable cost.
In SAGD, limiting the fluid production from the extraction chamber to liquids (i.e. hot water and hot bitumen) is called steam trap control. This steam trap control should reduce the use of steam as compared to say a cyclic steam extraction (so called “huff and puff”) because live steam is unavoidably vented during the “puff” production phase of the latter process thereby greatly reducing the thermal efficiency of the extraction. But this has not proved to be the case.
Maintaining the liquid submergence by controlling the fluid withdrawal rate is very challenging. If the liquid drainage at the rate at a particular location along the horizontal production well is too slow, the fluid level at that location can rise and even submerge the vapour injection well. In SAGD, locations that are flooded cannot be effectively heated by the injected steam, leading to a risk of having the bitumen cool down in that local area, become too viscous to drain, and thereby render portions of the horizontal well less productive or even completely unproductive.
In some reservoirs the extraction chamber can detach from the injection well and expand upwards until the stream reaches the top of the pay zone. This is very undesirable because the steam heating may become focused on the cap rock at the top of the pay zone which is unproductive, and fluid drainage to the production well may be limited to a few “chimneys”. Further this misplaced heating may allow the production well to cool off so much that produced fluids in the liquid sump become too viscous to flow without excessive pressure drive. This has been referred to as “pancaking” of the steam chamber.
One way to address the pancaking risk is to use very high drawdown pressures across the production well to try to aggressively drain any mobilized fluids. Unfortunately, aggressive drawdown pressures also inevitably leads to steam vapour breakthrough at one or more locations along the length of the horizontal well and direct production of steam through the production well. Direct production of steam leads to high energy consumption and excess greenhouse gas production both of which are expensive and highly undesirable as outlined below.
Heat balance calculations suggest that currently about half of the latent heat from steam injected into SAGD wells cannot be accounted for. However, the water material balance for most SAGD projects is quite reasonable, so steam (water) isn't “lost” even though its latent heat cannot be accounted for. Government funded studies report that the ideal energy requirement for SAGD should be in the range of 0.6 to 0.75 GJ per barrel of bitumen, which is much less than is actually being achieved in a typical facility. Based on the greenhouse gas emissions, as reported by environment Canada and production data for thermal oil projects as reported by the ERCB, the GHG intensity for thermal oil in Alberta averaged about 90 kg CO2 eq/bbl in 2009. Since natural gas is the primary fuel, the energy requirement for thermal oil in 2009 was about 1.6 GJ/bbl or more than twice as high predicted by the studies. This discrepancy can only be explained by an excess of steam being directly produced through the production well.
What is desired is a better way to limit the inflow of steam or vapour into a production well and in particular to a horizontal production well of the type used in a gravity drainage extraction process. Most preferably such a way of limiting flow would be compatible with high drawdown pressures of the type typically used in SAGD production.
U.S. Pat. No. 7,290,606 to Coronado et al presents a form of inflow control valve for a production well that can block the inflow of water, for example, into an oil well. This patent teaches using a moveable flapper valve or rotating valve at the end of an inlet passageway between an annulus and an inside of the production tubing. The patent teaches that the moveable valve is responsive to the fluid density surrounding the valve, i.e. within the production tubing. However, this design has several problems that make it unsuitable for SAGD applications or any other processes that operate close to bubble point conditions as set out below.
A first problem is that in some embodiments the moveable valve is designed in a way that permits it to be actuated by pressure drawdown. For example, pressure drop exerts an opening force on the flappers of designs shown in FIGS. 3A, 3B and 3C of U.S. Pat. No. 7,290,606, (column 7 lines 51-63) leaving these designs vulnerable to open inappropriately. This would permit vapour to escape by reason of drawdown pressure, which is the exact problem that operators currently face.
A second problem is that the flow restriction element may be located downstream of a flow passageway from the annulus. This downstream position renders the design unsuitable for SAGD because a small reduction in pressure within the production tubing can lead to substantive flashing of bubble point liquid into the vapour phase. A flow restriction element positioned downstream will be affected by vapour within the production tubular and tend to keep the valve closed, even though the production well may be fully submerged in liquid.
A third problem, is responsiveness since, as shown in FIGS. 6 and 7 of Coronado, sleeve 242 is symmetrical and evenly balanced. Eventually, if exposed to water, it would close, but in a dirty and viscous environment, such as normally found in SAGD production (with high viscosity bitumen and grit or sand), the meta-stable design will be slow to overcome the unavoidable and inevitable friction. Thus, the design favours and is intended for a one time shut-off, rather than a more responsive open/closed./open etc. valve as is required for example in SAGD.
A final problem is that the valve taught aligns itself with a predetermined orientation upon being positioned within the well bore, and then may be sealed to the casing, for example, with expanding seals. Such an alignment perpetuates the meta-stable position of the flow restriction element, thus ensuring the valve is unresponsive to changes in conditions. These and other limitations that will be apparent to those skilled in the art mean that this prior art device is of limited, if any, use in gravity drainage processes.
An inflow control device for SAGD is described by Wat et al Canadian Patent Application 2,692,939. FIG. 6 shows this device uses pressure drop across the valve to regulate the flow. A problem with a device which responds to pressure drop is that the pressure drop is not necessarily related to liquid levels in the sump around the production well.
What is desired therefore is a device that is suitable for use in a gravity drainage extraction process such as SAGD and which overcomes the issues associated with the prior art designs. Most preferably such a design would be able to rapidly and accurately respond to the presence or absence of liquid in the annulus to permit liquid bitumen to flow into a production well while preventing excess production of vapours such as steam. Such a design would not align itself with a predetermined position, but would move or change position as required to achieve optimum operation. Most preferably such a design would open and close without regard to the size of any pressure draw downs across the valve that might be required to ensure good SAGD performance and drainage across the reservoir. Such a device must be capable of effectively draining liquid from the chamber, to prevent flooding and pancaking. Such a device must be physically robust, operating for long periods of time and reliably rapidly cycling open and closed as the produced liquids are drained from the annulus and then allowed to refill, before being drained again.